Natural gas is a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formation beneath the earth's surface, often in association with petroleum. As obtained from oil and gas wells, raw or sour natural gas contains a number of impurities which must be removed before being introduced into a pipeline. The principal impurities in natural gas are water, carbon dioxide, and hydrogen sulfide. These undesirable components are conventionally removed from raw natural gas streams in gas processing plants. The processing plants are normally located in the field and vary in size from small units to large, centrally located plants.
Hydrogen sulfide is malodorous, poisonous and, when burned, the major cause of acid rain. When gaseous or liquid fuels containing hydrogen sulfide are burned, sulfur dioxide and water are formed. Acid rain is essentially an aqueous solution containing SO.sub.2, SO.sub.2 *6H.sub.2 O and sulfurous acid (H.sub.2 SO.sub.3).
The composition of raw natural gas varies widely from field to field. For example, the methane content can vary between 45 percent and 96 percent by volume, while the hydrogen sulfide, H.sub.2 S, content may range from 0.1 parts per million (ppm) to 150,000 ppm.
Since hydrogen sulfide is corrosive in the presence of water and poisonous in very small concentrations, it must be almost completely removed from natural gas streams before use and preferably before transport or processing in oil field equipment, pipelines, and refineries. As a result, many pipeline specifications limit the amount of hydrogen sulfide to less than 0.25 grains per 100 cubic feet of gas. Accordingly, removal of H.sub.2 S from hydrocarbons, e.g., natural gas, crude oil, and refined oil products is an important concern. Further, because of the large quantities of hydrocarbon material to be treated, it is important to have a means of removal that is economically efficient.
The technology known in the art for removing hydrogen sulfide from raw natural gas was developed for large processing plants to remove hydrogen sulfide in continuous processes. These large processing plants are fed by one or more natural gas wells, each of which may produce over 10 million cubic feet of natural gas per day. Many of these processes utilize commodity chemicals or proprietary materials to lower the hydrogen sulfide levels in natural gas to pipeline specifications. Also, many of these processes not only sweeten sour natural gas to pipeline specifications, but also regenerate most, if not all, of the sweetening compositions involved.
Complicating the removal problem is the fact that some treatments will have one or more good performance characteristics, but will also have some undesirable performance characteristic(s). For instance, many treatments are difficult to handle because of their viscosity, pour point, tendency to form water emulsions, or toxicity. The solubility of the treatment additive is often of paramount importance. Because of the demanding performance characteristics required of a hydrogen sulfide scavenger, the chemistry available is very limited.
U.S. Pat. No. 2,426,318 discloses a method of inhibiting the corrosive action of natural gas and oil containing soluble sulfides on metals by utilizing certain aldehydes, preferably formaldehyde. Although the aldehydes are effective in selectively reducing the sulfide levels of natural gas, they are known to form trithiane compounds upon reaction with the sulfides. The trithianes are solids which do not easily dissolve and can clog gas lines. Furthermore, aldehydes are unstable, temperature sensitive and have a tendency to polymerize. Moreover, aldehydes are known carcinogens and environmentally hazardous. For these reasons, the use of aldehydes for sweetening natural gas has come into disfavor.
U.S. Pat. No. 4,515,759 discloses a buffered aqueous solution of sodium nitrite which is injected into scrubber towers to sweeten natural gas. This system is not regenerable, limiting its use to batch processes, and produces undesirable solid elemental sulfur.
U.S. Pat. No. 4,978,512 (Dillon) discloses a method for selectively reducing the levels of hydrogen sulfide and organic sulfides from gaseous and/or liquid hydrocarbon streams, particularly natural gas streams, by contacting the streams with the reaction product of an alkanolamine with a monoaldehyde. The patent also discloses that the reaction product may be mixed with a glycol prior to contact with the gas in order to reduce the water levels in the gas.
U.S. Pat. No. 5,128,049 (Gatlin) discloses a method of using triazines as hydrogen sulfide scavengers.
U.S. Pat. No. 5,169,411 (Weers) discloses a method for preventing liberation of H.sub.2 S in crude oil or petroleum residuum medium with imines.
U.S. Pat. No. 5,266,185 (Weers) discloses the suppression of hydrogen sulfides in a heavy hydrocarbon derived from heavy crude oil by contacting the petroleum with the reaction product of a heterocyclic aldehyde and an organic primary amine. The useful compound was described as an imine.
U.S. Pat. No. 5,284,576 (Weers) discloses a process for scavenging hydrogen sulfide using a scavenger prepared by reacting an alkylenepolyamine, including diethylenetriamine, and formaldehyde. In Example 1, column 4, lines 10-16, Weers taught that formaldehyde should be added to a flask of diethylenetriamine. However, this reaction results in a gel which is very difficult to handle and makes the product entirely unsuitable for use as a hydrogen sulfide scavenger.
U.S. Pat. No. 5,314,672 (Vasil) discloses a method of selectively reducing the levels of hydrogen sulfide and organic sulfides by contacting natural gas with the reaction product of ethylenediamine and 50% uninhibited aqueous formaldehyde.
Although many compositions of amine-aldehyde condensation products and methods for their use for reducing hydrogen sulfide in hydrocarbon streams have been developed, the problem has not been effectively resolved as evidenced by the number of recently issued patents which disclose alternative methods. Many of the amine-aldehyde compounds which have previously been developed are unstable, or must be added in cost prohibitive amounts to effectively reduce the hydrogen sulfide levels in natural gas.
Various of the above, prior art scavengers contain excess, unreacted formaldehyde. While formaldehyde may act as a hydrogen sulfide scavenger, it forms a compound which is both crystalline and carcinogenic. Therefore, it is highly undesirable to have a scavenger system which contains any free or unreacted formaldehyde.
Despite the above efforts, there remains a need in the art for an efficient and cost effective method and scavenger for selectively reducing the levels of hydrogen sulfide and organic sulfides found in sour hydrocarbon streams and aqueous systems which has reduced toxicity, remains soluble upon reaction with hydrogen sulfide and organic sulfides, and does not form gels during the process of manufacturing the scavenger.
Although this invention concerns hydrogen sulfide "suppression", it is important to understand that no single composition can be certain to economically remove all hazardous levels of hydrogen sulfide under all circumstances. That is, hydrogen sulfide may appear in hazardous concentrations after a treatment that in similar circumstances had successfully suppressed hazardous concentrations. It is important that all potential sources of hydrogen sulfide be monitored and that any suppression means not be relied upon as infallible.